Exploration & Development in Southern Caribbean Frontier Basins - Presentation Proposal Form
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Interpretations of thermal maturation provide critical data needed for both conventional and unconventional resource
assessments. The absence of true vitrinite in pre-Devonian sediments eliminates one of the most commonly measured
geothermometers used for thermal maturity determination. Programmed pyrolysis parameters like Tmax can be of limited utility
given the maturity regime. However, other organic macerals are potentially available to constrain thermal maturity. The current
organic petrology study has been undertaken to provide a very detailed comparison of reflectance measurements on
pyrobitumens, “vitrinite-like” material and graptolites.
In the Appalachian Basin of North America, Cambrian-aged source rocks were deposited in shallow water mixed carbonate-siliciclastic depositional environments. Solid pyrobitumen material is found to occur in both lenticular lens/layer morphology as
well as distinct pore-filling angular varieties. Published formulas to calculate Equivalent Reflectance (Eq. Ro) from solid
bitumens have been applied to these discrete morphological populations. In addition, a newly developed formula to calculate Eq.
Ro from angular pyrobitumen (VRc=0.866*BRo ang + 0.0274) is introduced based upon statistical evaluation of reflectance
readings from a global dataset. “Vitrinite-like” organic macerals were found in rare abundance within these potential source
rocks, but their occurrence enables an independent comparison to pyrobitumen Eq. Ro values. Graptolites are another organic
maceral that can be evaluated via organic petrology, but caution should be utilized since these tend to show a high degree of
anisotropy. The results of this investigation provide additional geochemical guidance to assist geologists in more accurately
interpreting thermal maturity in the Rome Trough region of the Appalachian Basin.
Rock-Eval hydrogen index (HI) is often used to compare relative maturities of a source horizon across a basin. Usually, there are
measurements from the source horizon at a single well, and the mean
hydrogen index is calculated, or the S2 is plotted against TOC. The slope
of the best fit line through that data is used as the representative HI for that well (sometimes referred to as the ‘slope HI
’ methodology). There
is a potential flaw in both these
methodologies; however, that renders the calculated HI as misleading if the source horizon being examined is
not relatively uniform in source quality, vertically in the stratigraphic column. From a geologic perspective, it would be unusual for the source
rock quality not to vary vertically in the stratigraphic column. Organic matter input, preservation, dilution, and sediment accumulation rate
typically vary in many depositional environments over the millions of years required to create a thick source rock
package. Nevertheless, there
are source rocks which do display remarkable source-quality uniformity from top to bottom of the stratigraphic package. We have examined
source rocks from several basins where the source quality is relatively uniform over the stratigraphic column, and source rocks where the
source quality varies greatly over the stratigraphic column. Methodologies to assess hydrogen index at specific wells for the
se two scenarios
differ. Most geoscientists may not be familiar with why a single technique is not suitable for both these scenarios, or how to correctly use
hydrogen index as a relative maturation proxy in the case where source rock quality is not uniform. We will demonstrate how to determine if
your source rock quality is uniform or varied relative to HI over the stratigraphic column, and how to assign a hydrogen index to the different
source facies when that source rock quality is not uniform. Further we will illustrate how to estimate the original hydrogen
index of the
different source facies and assign each a transformation ratio. The transformation ratio is a better proxy for relative maturity, since different
source facies may have different present-day hydrogen indices, but their present-day transformation ratio should be quite similar.
The assessment of the natural temporal
variability of source rock units is critical for the understanding of petroleum systems as changes in
mineral matrix, organic matter (OM) concentration,
and composition can significantly affect expulsion efficiency, primary and secondary
migration processes, hydrocarbon quality as well as oil source rock correlation. Already small-scaled fluctuations within sediment successions
can critically influence migration efficiency. High-resolution investigation of a well-preserved Lower Jurassic drill core (Toarcian Posidonia
Shale) revealed seven discrete and systematic intervals of deviating source rock quality. These were composed of homogenized,
marls of light grey color, opposed to laminated dark grey background sedimentation. Both lithotypes differentiate not only in mineral
composition, but particularly in OM content and quality. An average TOC content of app. 3.9 wt.% reached by the grey marl, is
faced by an
average TOC content of app. 7.8 wt.% measured for the laminated dark grey marls. Average
hydrogen index for grey non-laminated marls was
app. 550 mg HC/g TOC, whereas much higher source rock quality with 780 mg HC/g TOC was attained in the dark laminated marls.
lower OM concentration and inferior OM quality generates important domains for preferential migration of products, originated from the dark
grey layers, or hydrocarbon cluster in case of limited migration into adjacent reservoirs. To assess the potential for preferential intake of
hydrocarbons by the coarser-grained light marls and their qualification as migration avenues, artificial maturation experiments were performed
with both lithotypes. Hydrocarbon generation was simulated by hydrous pyrolysis in two successive temperature steps 330 °C and 360 °C,
covering an early maturity stage, as well as the end of the oil window. Both lithologies show striking differences, not only for the extract yield,
but also for the timing of generation. OM quality differences were reflected by variable n-alkane distributions and molecular maturity
parameters. High-resolution continuous data produced by non-destructive techniques allows to draw conclusions on i) source rock potential,
ii) expulsion and migration processes
and iii) on prediction of petroleum accumulation within the sediment succession. High-resolution
investigation in combination with artificial maturation experiments represent an easy-to-use tool in petroleum system analysis.
The driving forces for conventional accumulations (structural or stratigraphic traps) are Forces of Buoyancy which are due to
densities of hydrocarbons and water. In contrast, the driving forces for unconventional tight accumulations are Forces of Expulsion which are
produced by high pressures. That is an enormous difference and creates unconventional petroleum systems that are characterized by very
different and distinctive characteristics. The Force of Expulsion pressures are created by the
significant increase in volume when any of the
three main kerogen types are converted to hydrocarbons. At those conversion times in the burial history, the rocks are already sufficiently tight
so the large volumes of generated hydrocarbons cannot efficiently escape through the existing tight pore system,
thus creating a permeability
bottleneck that produces an overpressured compartment over a large area corresponding to the proper thermal oil and gas maturities for that
basin. The forces initially created
in these source rocks can only go limited distances into adjacent tight reservoirs (clastics or carbonates)
above or below the source. The exact distance will vary depending on the pressure increase, matrix permeability, and fractures of that specific
tight reservoir system. In general, the distances are small, in the orders of 10s to 100s of feet for oil and larger for more mobile gas systems.
Those exact distance numbers are subject to ongoing investigations.
A plot of the pressure data versus elevation
for a given formation is critical in determining whether an accumulation is conventional or
unconventional. Conventional accumulations will have hydrocarbon columns of 10s to 100s of feet with the pressure in the hydrocarbons and
that in the water equal at the bottom of the accumulation (at the HC-water contact). In contrast, the unconventional accumulations will show
HC column heights of 1000s of feet with the pressure in the hydrocarbon phase and the water phase being the same at the top of the
accumulation (at the updip transition zone). Those significant differences are critical for understanding and differentiating these two play types.
Because the system is a pore throat bottleneck with very little or minimum lateral migration, the type of hydrocarbon
s are closely tied to the
thermal maturity required to generate those hydrocarbons. Thus the play concept begins with two important geochemical considerations: (1)
where are the source rocks and what are the kerogen types and organic richness (TOC), and (2
) where are they mature in the basin for oil,
condensate, and gas in the basin. These parameters will very quickly define the fairway for the play. Then one has to add the
information on the reservoirs themselves: composition (brittleness), thickness, and reservoir quality (matrix porosity and permeability). In
summary, these tight unconventional petroleum systems (1) are dynamic
and (2) create a regionally inverted petroleum system with water over
oil over condensate over gas for source rocks wit
h Type I or II kerogen types.
The search for unconventional hydrocarbons is not new. It’s true that almost 100 years separated the early exploration successes in the synclinal valleys of Central Pennsylvania, to the exploitation of Coal-Bed Methane in a number of basins in the U.S. and Canada in the 1980’s. Since the 1980's, however, a quiet revolution began which by today has seen several waves of unconventional resources being pursued with economic success. Coal-bed methane was followed by the search for Center-Basin Gas, Shale Gas and most recently, Liquid-rich Shales (some of which aren't shales).
The Arctic Ocean occupies a unique tectonic setting as a small, confined ocean between two much larger oceans - the subducting Pacific margin and the opening North Atlantic. Unlike many of the world's oceans, evidence on both timing and geometry is poor, and major elements of the plate tectonic evolution are still "up for grabs". The Arctic has experienced significant plate motion from Cretaceous to present, and because of the ambiguities in the oceanic signature, resolving the most likely kinematic history is critical in understanding paleogeography and hence reservoir and source distribution. I will show a 3-stage kinematic model which, while not a unique solution, seems to best satisfy the known constraints.
The AAPG Latin America & Caribbean Region and the Colombian Association of Petroleum Geologists and Geophysicists (ACGGP) invite you join us for GTW Colombia 2020, a specialized workshop bringing leading scientists and industry practitioners to share best practices, exchange ideas and explore opportunities for future collaboration.
The 2-day workshop brings together technical experts and industry leaders from Colombia and throughout the Americas to take a multidisciplinary look at future opportunities for exploration and development of Southern Caribbean Frontier Basins.
The gas transport in organic-rich shales involves different length-scales, from organic and inorganic pores to macro- and macrofractures. In order to upscale the fluid transport from nanoscale (flow through nanopores) to larger scales (to micro- and macrofractures), multicontinuum methodology is planned to be used.
The Niobrara Petroleum System of the U.S. Rocky Mountain Region is a major tight petroleum resource play.
This e-symposium is ideal for geologists, geophysicists, engineers and other geoscientists who are involved in gas shale exploration and production.
Expanded package for CEU credit is $100 for AAPG members, and $145 for non-members. Special Student Pricing: $25 for Webinar only; $35 for Expanded package.
The geochemistry of formation fluids (water and hydrocarbon gases) in the Uinta Basin, Utah, is evaluated at the regional scale based on fluid sampling and compilation of past records.
This course introduces the learner to the fundamentals of shale gas, including current theories that explain its origin, and how to determine which reservoirs are commercially viable.
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